Tapered Blade Profile on an Outer Bit

ABSTRACT

In one aspect of the present invention, a drill bit assembly is configured for downhole drilling. The drill bit assembly comprises an outer bit with a plurality of outer blades and a bore disposed within an outer cutting face. In addition, the outer bit comprises a rotational axis. The drill bit assembly comprises an inner cutting face that is configured to cut a hole with an inner gauge diameter in front of the outer bit. At least one outer blade on the outer bit comprises a central most cutter configured to degrade the inner gauge diameter. The central most cutter is axially and laterally displaced from the second most central cutter on the at least blade such that less than fifty percent of the central most cutter axially and laterally overlaps the second most central cutter.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation in part of U.S. patent application Ser. No. 12/894,371, which was a continuation in part of U.S. patent application Ser. Nos. 12/752,323, which was filed on Apr. 1, 2010; 12/755,534, which was filed on Apr. 7, 2010; and 12/828,287, which was filed on Jun. 30, 2010. All of these applications are herein incorporated by reference for all that they contain.

BACKGROUND OF THE INVENTION

The present invention relates to drill bit assemblies, specifically drill bit assemblies for use in subterranean drilling. More particularly, the present invention relates to drill bits that include an inner bit. The prior art discloses drill bit assemblies comprising inner bits.

One such bit is disclosed in U.S. Pat. No. 4,862,974, to Warren et al., which is herein incorporated by reference for all that it contains. Warren et al. discloses a downhole drilling apparatus for use with an under gauge drill bit comprising a downhole drilling motor which includes a housing and means for rotating the drill bit relative to the housing about an axis of rotation. The apparatus also comprises stabilizers connected to the housing for stabilizing the drill bit, and it further comprises cutters connected to the housing for cutting a borehole wall created by passage of the drill bit, wherein the cutters extend radially outwardly relative to the axis of rotation to a greater extent than does the drill bit. A drilling assembly including such a drilling apparatus and a method of drilling a substantially vertical borehole in an earthen formation utilizing such an apparatus are also disclosed.

U.S. Pat. No. 5,765,653, to Doster et al., which is herein incorporated by reference for all that it contains. Doster et al. discloses a method and apparatus for reaming or enlarging a borehole with enhanced stability. A pilot stabilization pad (PSP) having an axially and circumferentially tapered entry surface and a circumferential transition surface above is employed to enhance the transition from the smaller diameter borehole to be enlarged while accommodated the side force vector generated by the cutting assembly used to effect the enlargement. In addition, one or more eccentric stabilizers are employed above the reaming apparatus to laterally or radially stabilize the bottomhole assembly, which may comprise either a straight-hole or steerable, motor-driven assembly.

U.S. Pat. No. 7,712,549 to Dennis et al., which is herein incorporated by reference for all that it contains. Dennis et al., discloses a drilling tool that includes a pilot bit and a plurality of mills encircling the pilot bit. The pilot bit and the plurality of mills are each driven by a separate, hydraulically powered turbine or positive displacement motor. The drilling tool does not include a transmission for transmitting power from the turbine or motor to any of the plurality of mills or the pilot bit.

BRIEF SUMMARY OF THE INVENTION

In one aspect of the present invention, a drill bit assembly is configured for downhole drilling. The drill bit assembly comprises an outer bit with a plurality of outer blades and a bore disposed within an outer cutting face. In addition, the outer bit comprises a rotational axis. Furthermore, the drill bit assembly comprises an inner bit that is rotationally isolated from the outer bit and disposed within the bore. The inner bit comprises an inner cutting face and is configured to degrade the inner gauge diameter. The central most cutter is axially and laterally displaced from the second most central cutter on the at least one blade such that less than fifty percent of the central most cutter axially and laterally overlaps the second most central cutter.

The central most cutter and second most central cutter of the outer bit may be aligned on a linear segment of the at least one outer blade. The central most cutter and second most central cutter of the outer bit may be aligned on a convex segment of the at least one outer blade. The central most cutter and second most central cutter of the outer bit may be aligned on a concave segment of the at least one outer blade.

The inner bit of the drill bit assembly may be configured to rotate faster than the outer bit. In some embodiments, the inner and outer bits are rotationally fixed together, and in other embodiments, the inner and outer bits are configured to rotate in opposite directions. The inner bit may comprise a center indenter. The inner bit may protrude from the outer bit.

The outer bit of the drill bit assembly may be rigidly connected to a drill string and the inner bit may be rigidly connected to a torque transmitting device disposed within the drill string. The torque transmitting device may be configured to provide the inner bit with power such that the work done per unit area of the inner bit is greater than the work done per unit area of the outer bit. The inner bit may be configured to steer the drill bit assembly by pushing off the outer bit. The outer bit may be configured to rotate in a first direction and the inner bit may be configured to rotate in a second direction. The inner bit may be disposed eccentric with respect to the outer bit.

The drill bit assembly may comprise at least one fluid nozzle disposed on both the inner bit and the outer bit. In addition, at least one fluid nozzle may be incorporated into a gauge of the inner bit. The fluid nozzle may be configured to convey fluid across a working face/blade of the outer bit.

The shape of the outer blade on the outer bit may be configured to apply force to the inner gauge diameter further degrading degrading the formation beginning close to the center and progressing outwards. The inner bit may be configured to weaken the formation prior to the outer bit degrading the formation. The outer bit may be configured to degrade the weakened formation easier than a formation that has not been weakened.

The central most cutter on the outer bit may be axially displaced from the second most central cutter such that there is no axial overlap. The central most cutter may be laterally displaced from the second most central cutter such that there is no lateral overlap.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a perspective diagram of an embodiment of a drilling operation.

FIG. 2 is a cross-sectional diagram of an embodiment of a drill bit assembly.

FIG. 3 is a perspective diagram of an embodiment of a drill bit assembly.

FIG. 4 is a perspective diagram of an embodiment of a drill bit assembly.

FIG. 5 is a perspective diagram of an embodiment of a drill bit assembly.

FIG. 6 is a perspective diagram of an embodiment of a drill bit assembly.

FIG. 7 is a diagram of an embodiment of a cutter profile.

FIG. 8 a is an orthogonal diagram of an embodiment of a drill bit.

FIG. 8 b is an orthogonal diagram of an embodiment of a drill bit.

FIG. 9 is an orthogonal diagram of an embodiment of a drill bit assembly.

FIG. 10 is an orthogonal diagram of an embodiment of a drill bit assembly.

DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED EMBODIMENT

Referring now to the figures, FIG. 1 discloses a perspective diagram of an embodiment of a drilling operation comprising a downhole drill string 100 suspended by a derrick 101 in a bore hole 102. A drill bit assembly 103 may be located at the bottom of the bore hole 102 and may comprise a drill bit 104. As the drill bit 104 rotates downward the downhole drill string 100 advances farther into the earth. The downhole drill string 100 may penetrate soft or hard subterranean formations 105. The downhole drill string 100 may comprise electronic equipment able to send signals through a data communication system to a computer or data logging system 106 located at the surface.

FIG. 2 discloses a cross-sectional diagram of an embodiment of a drill bit 104. The drill bit 104 may comprise an outer bit 201 and an inner bit 202. The outer bit 201 may comprise a rotational axis 203 and a plurality of outer blades 204. Additionally, the outer bit 201 may comprise a bore 221 disposed within an outer cutting face 222. The inner bit 202 may be disposed within the bore 221 of the outer bit 201. The inner bit 202 may comprise an inner cutting face 205 and a center indenter 206. The center indenter 206 may be the first to contact the formation (see FIGS. 3-6) during normal drilling operations and may weaken the formation.

In this embodiment, the outer bit 201 is rigidly connected to the drill string 100 and the inner bit 202 is rigidly connected to a torque transmitting device 207 disposed within the drill string 100. The torque transmitting device 207 may be configured to provide the inner bit 202 with power such that the work done per unit area of the inner bit 202 is greater than the work done per unit area of the outer bit 201. The torque transmitting device 207 may be a mud driven motor, a positive displacement motor, a turbine, electric motor, or combinations thereof. The inner bit 202 and the torque transmitting device 207 may be substantially collinear with the rotational axis 203. The torque transmitting device 207 may comprise a gearbox 208 to apply a preferential torque to the inner bit 202.

The inner bit 202 may be rotationally isolated from the outer bit 201. When the inner bit 202 is rotationally isolated from the outer bit 201, the direction and rotational speed of the inner bit 202 may be independent of the direction and rotational speed of the outer bit 201. In this embodiment, the torque transmitting device 207 may exclusively control the direction and speed of the rotation of the inner bit 202. It is believed that having the inner bit 202 rotationally isolated from the outer bit 201 may be advantageous because the torque transmitting device 207 may rotate the inner bit 202 independent of the drill string 100. The outer bit 201 may be configured to rotate in a first direction controlled by the drill string 100 and the inner bit 202 may be configured to rotate in a second direction controlled by the torque transmitting device 207. The torque transmitting device 207 may be rotationally isolated from the drill string 100 such that the torque transmitting device 207 may rotate the inner bit 202 in the second direction without compensating for the rotation of the drill string 100.

The embodiment of FIG. 2 also discloses the inner bit 202 protruding from the outer bit 201. The inner bit 202 may be configured to move axially with respect to the outer bit 201 such that the inner bit 202 may protrude and retract within the outer bit 201. The inner bit 202 may be configured to steer the drill bit assembly 103 by pushing off the outer bit 201. The torque transmitting device 207 and the inner bit 202 may be rigidly connected to a piston 211 in a piston cylinder 220. The piston 211 may comprise a first surface 218 and a second surface 219. The piston 211 may separate the cylinder 220 into a first pressure chamber 213 and a second pressure chamber 214. A first fluid channel 215 may connect the first pressure chamber 213 to at least one valve 217 and a second fluid channel 216 may connect the second pressure chamber 214 to the at least one valve 217. The at least one valve 217 may control the flow of drilling fluid to the first and second fluid channels 215, 216 to control axial displacement of the piston 211 by forcing the fluid against first and second piston surfaces 218, 219. As fluid enters either the first or second pressure chambers 213, 214 fluid in the other chamber is exhausted out of the cylinder 220.

A method of increasing the rate of penetration in downhole drilling may comprise protruding the inner bit 202 from the outer bit 201 and rotating the inner bit 202 at a higher angular speed than the outer bit 201. The step of rotating the inner bit 202 at a higher angular speed than the outer bit 201 may comprise rotating the inner bit 202 through the torque transmitting device 207, as the drill string 100 rotates the outer bit 201. It is believed that protruding the inner bit 202 from the outer bit 201 and rotating the inner bit 202 at a higher angular speed than the outer bit 201 allows the inner bit 202 to weaken the formation. The outer bit 201 may degrade the weakened formation at a rate greater than if the formation had not previously been weakened by the inner bit 202.

FIGS. 3-6 disclose perspective diagrams of an embodiment of a drill bit assembly 103. In FIG. 3, the drill bit assembly 103 is disclosed traveling in the direction of the arrow 300 through a bore hole 102 previously formed. The inner bit 202 may protrude from the outer bit 201 and may comprise an inner cutting face 205. The inner cutting face 205 may comprise a plurality of shear cutters. The outer bit 201 may comprise a plurality of outer blades 204. At least one outer blade 204 may comprise a central most cutter 302 and a second most central cutter 303 aligned along a linear blade segment.

FIG. 3 further discloses at least one fluid nozzle 304 that may be incorporated into a gauge of the inner bit. The at least one nozzle 304 may be configured to convey fluid across a working face of the outer bit 201. The at least one fluid nozzle 304 may be aligned such that fluid may pass over the plurality of outer blades 204. During normal drilling operations, pieces of the formation 105 may be deposited onto the outer blades 204 causing the outer blades 204 to less effectively engage in the formation 105. Fluid may be expelled from the at least one nozzle 304 such that the fluid directly or tangentially strikes the outer blades 204 removing any formation deposited on the outer blades 204. Fluid from the at least one nozzle 304 may also remove degraded formation from the bottom of the bore hole 102 through an annulus of the bore hole 102.

FIG. 4 discloses the inner bit 202 as it begins to engage the formation 105. The inner bit 202 may degrade the formation 105 in front of the outer bit 201 by forming a leading bore with an inner gauge diameter 450 in the wellbore floor. The leading bore may weaken the formation 105 immediately around the inner gauge diameter because the leading bore relieves the formation's pressure. The weakened region 400 is represented by the discontinuous line. The weakened region may require less energy to degrade; thereby requiring a lower applied force from the outer bit 201.

FIG. 5 discloses the outer blade beginning to engage in the weakened region. The central most cutters 302 of the outer blades 204 may be configured to degrade the formation at the inner gauge diameter 450 that was formed by the inner bit 202. The axial and lateral displacement of the cutters 302, 303 may allow the central most cutters 302 to engage the inner gauge diameter prior to the second most central cutter 303 and successive cutters engage the wellbore floor. As the inner gauge diameter is widened by the central most cutter, the weakened region is believed to enlarged proportionate to the increased width of the inner gauge diameter. The weakened region is believed to expand because the removal of more material out of the leading bore further relieves the formation pressure.

FIG. 6 discloses the drill bit 104 having progressed farther into the formation 105. The second most central cutter may 303 is shown degrading the formation 105, in addition to the central most cutter 302. The central most and the second most central cutters 302, 303 may further degrade the formation 105 beginning at the inner gauge diameter and traveling outwards. The successive cutters may further degrade the formation 105, widening the leading bore to a full gauge diameter of the wellbore.

The central most cutter 302 and the second most central cutter 303 (as well as the successive cutters) may be aligned on a linear portion of the at least one outer most blade 204 of the outer bit 201. The central most cutter 302 may be axially and laterally displaced from the second most central cutter 303 such that less than 50% of the central most cutter 302 axially and laterally overlaps the second most central cutter 303. In some embodiments, the central most cutters 302 may be axially displaced from the second most central cutter 303 such that there is no axial overlap. In some embodiments, the central most cutters 302 may be laterally displaced from the second most central cutter 303 such that there is no lateral overlap.

The prescribed novel arrangement of cutters on the outer blade has significant advantages over the prior art references known to the Applicants. For example, if the cutters on the outer blade overlapped axially more than 50%, the second most and successive cutters would engage the wellbore floor in an area outside of the weakened region. If this occurs, the non-weakened region will limit the penetration rate of the drill bit because the non-weakened region will resist the drilling action more than the weakened region.

Further, axial overlap greater than 50% is believe to result in degrading the wellbore floor in areas not at or immediately adjacent the inner gauge diameter. This is significant because it is believed that the most efficient mechanism for degrading the formation with the outer blade cutters is by progressively expanding the inside of the leading bore (inside out degradation) until the leading bore is the same width as the full gauge diameter of the wellbore. A inside out degradation is believed to be more effective than degrading the straight down from the wellbore floor (straight down degradation) because the straight down degradation does not take advantage of the pressure relief provided by the leading bore.

In some formations, the weakened region may comprise a distinct boundary, however, many rock formations will likely experience a weakened continuum that results in the formation being weaker closer to the inner gauge diameter and harder the farther away the formation area is from the inner gauge diameter. But, regardless of the weakened region's characteristics, the cutter profile on the outer blade with less than 50% axial overlap is believed to provide the best overall cutter profile efficiency.

Also if the outer blade cutters overlapped laterally more than 50%, then the cutters will not expand the leading bore by cutting into the inner gauge diameter as efficiently as possible. The more lateral overlap between the outer blade cutters, then less the successive outer blade cutters will contribute to degrading the formation because the loads will disportionately fall upon the central most cutter.

FIG. 7 discloses an embodiment of a cutter profile 700 relative to the rotational axis 203. The cutter profile 700 may comprise an outer bit profile 701 and an inner bit profile 702. The inner bit profile 702 protrudes from the outer bit profile 701. The outer bit profile 701 and the inner bit profile 702 may overlap laterally. The overlapping may occur at the outer end of the inner gauge diameter and at the inner most cutter of the outer bit. It is believed that the overlapping of the outer bit profile 701 and the inner bit profile 702 may increase the service life of the drill bit. This may provide redundancy at the transition between the outer bit and the inner bit. By overlapping the outer bit profile 701 and the inner bit profile 702, the transition may be reinforced such that even if a first cutter breaks off, a second cutter may become engaged in the formation soon thereafter. Such overlapping may also reduce wear.

FIG. 8 a discloses the outer bit 201 configured to rotate in a first direction 800 and the inner bit 202 configured to rotate in a second direction 801. The first and second directions 800, 801 may be in the same direction or in reverse directions. The inner bit 202 may be disposed coaxial with the outer bit 201 such that the rotational axis of the outer bit 201 may also be the axis of rotation for the inner bit 202.

The bit may include shear cutters and/or pointed cutters. The area of engagement on the drill bit assembly 103 may include shear cutters, diamond enhanced cutters, pointed cutters, rounded cutters or combinations thereof. The pointed cutters may be better suited for the inner portions of both the working face of the inner and outer bit, while the shear cutters may be better suited for the gauge portions of the inner bit 202 and outer bit 201. The pointed cutters preferably comprise a rounded apex with a radius of curvature between 0.050 and 0.120 inches. The radius of curvature may be formed along a central axis of the cutter. The shear cutters may have sharp, chamfered, or rounded edges.

This embodiment further discloses at least one fluid nozzle 802 disposed on the outer bit 201 and at least one fluid nozzle 803 disposed on the inner bit 202. A fluid pathway may be disposed between the outer bit 201 and the inner bit 202. During normal drilling operations, the degraded formation 105 may be removed from the bottom of the bore hole to allow for greater drilling effectiveness. Fluid from the at least one fluid nozzle 802 on the outer bit and the at least one fluid nozzle 803 on the inner bit or from the fluid pathway may remove the degraded formation 105 from the bottom of the bore hole through an annulus of the bore hole.

FIG. 8 b discloses the inner bit 202 protruding from the outer bit 201. The inner bit 202 may be disposed eccentric with respect to the outer bit 201. During normal drilling operations, the inner bit 202 may rotate around the rotational axis of the outer bit 201. In another embodiment, the drill bit 104 may be configured to hammer the inner bit 202 into a formation. Hammering the inner bit 202 into the formation and rotating the inner bit 202 around the center axis may allow the inner bit 202 to weaken the formation through a combinations of mechanisms.

FIG. 9 discloses the central most cutter 302, a second most central cutter 303, and the successive cutters aligned on a convex segment of the outer blade 204. FIG. 10 discloses these cutters aligned on a concave segment of the outer blade 204.

Whereas the present invention has been described in particular relation to the drawings attached hereto, it should be understood that other and further modifications apart from those shown or suggested herein, may be made within the scope and spirit of the present invention. 

1. A drill bit assembly for downhole drilling, comprising: an outer bit with a plurality of outer blades and a bore disposed within an outer cutting face; the outer bit comprises a rotational axis; an inner bit that is rotationally isolated from the outer bit is disposed within the bore and comprises an inner cutting face; the inner bit is configured to cut a hole with an inner gauge diameter in front of the outer bit; at least one outer blade comprises a central most cutter configured to degrade the inner gauge diameter; and the central most cutter is axially and laterally displaced from the second most central cutter on the at least blade such that less than 50% of the central most cutter axially and laterally overlaps the second most central cutter.
 2. The drill bit assembly of claim 1, wherein the central most cutter and the second most central cutter are aligned on a linear segment of the at least outer blade.
 3. The drill bit assembly of claim 1, wherein the central most cutter and the second most central cutter are aligned on a convex segment of the at least one outer blade.
 4. The drill bit assembly of claim 1, wherein the central most cutter and the second most central cutter are aligned on a concave segment of the at least one outer blade.
 5. The drill bit assembly of claim 1, wherein the inner bit is configured to rotate faster than the outer bit.
 6. The drill bit assembly of claim 1, wherein the inner bit comprises a center indenter.
 7. The drill bit assembly of claim 1, wherein the inner bit protrudes from the outer bit.
 8. The drill bit assembly of claim 1, wherein the outer bit is rigidly connected to a drill string and the inner bit is rigidly connected to a torque transmitting device disposed within the drill string.
 9. The drill bit assembly of claim 8, wherein the torque transmitting device is configured to provide the inner bit with power such that the work done per unit area of the inner bit is greater than work done per unit area of the outer bit.
 10. The drill bit assembly of claim 1, further comprising at least one fluid nozzle disposed on both the inner bit and the outer bit.
 11. The drill bit assembly of claim 1, wherein at least one fluid nozzle is incorporated in a gauge of the inner bit, wherein the nozzle is configured to convey fluid across a working face of the outer bit.
 12. The drill bit assembly of claim 1, wherein the inner bit is configured to steer the drill bit assembly by pushing off the outer bit.
 13. The drill bit assembly of claim 1, wherein the outer bit is configured to rotate in a first direction and the inner bit is configured to rotate in a second direction.
 14. The drill bit assembly of claim 1, wherein the inner bit is disposed eccentric with respect to the outer bit.
 15. The drill bit assembly of claim 1, wherein the shape of the outer blade is configured to apply force to the inner gauge diameter, degrading it beginning at the center and progressing outwards.
 16. The drill bit assembly of claim 1, wherein the protruding inner bit is configured to weaken a formation, prior to the outer bit degrading the formation.
 17. The drill bit assembly of claim 16, wherein the outer bit is configured to degrade the weakened formation at a higher rate than a formation that has not been weakened.
 18. The drill bit assembly of claim 1, wherein the central most cutter is axially displaced from the second most central cutter such that there is no axial overlap.
 19. The drill bit assembly of claim 1, wherein the central most cutter is laterally displaced from the second most central cutter such that there is no lateral overlap.
 20. The drill bit assembly of claim 1, wherein the inner and outer bit are rotationally fixed to each other. 